Monitoring of Downhole Parameters and Tools Utilizing Fiber Optics

ABSTRACT

The present disclosure provides systems utilizing fiber optics for monitoring downhole parameters and the operation and conditions of downhole tools and controlling injection operations based on measurements in an injection well and/or a production well.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional application of U.S. patent applicationSer. No. 10/447,855, filed on May 29, 2003 which is a divisionalapplication of U.S. patent application Ser. Nos. 09/872,591 now U.S.Pat. Nos. 6,588,266 and 09/070,953 now U.S. Pat. No. 6,268,911.Divisional application Ser. No. 09/872,591 of U.S. patent applicationSer. No. 09/070,953 has issued as U.S. Pat. No. 6,268,911. U.S.application Ser. No. 09/923,059, now abandoned, is a divisional of U.S.patent application Ser. Nos. 09/070,953 and 09/872,591. The presentclaims are based on a restriction requirement in the divisionalapplication Ser. No. 09/872,591.

U.S. patent application Ser. No. 09/070,953 claims priority fromProvisional U.S. Patent Applications Ser. Nos. 60/045,354 filed on May2, 1997; 60/048,989 filed on Jun. 9, 1997; 60/052,042 filed on Jul. 9,1997; 60/062,953 filed on Oct. 10, 1997; 67/073425 filed on Feb. 2,1998; and 60/079,446 filed on Mar. 26, 1998. Reference is also made toU.S. patent application Ser. No. 09/071,764 filed on May 1, 1998, nowU.S. Pat. No. 6,281,489, the contents of which are incorporated here byreference. Patents have issued from additional applications Ser. Nos.09/778,696; 10/336,154; 10/674,248; 10/884,052; 10/884,057 and11/430,729 with priority claims to U.S. patent application Ser. No.09/071,764 filed on May 1, 1998.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates generally to oilfield operations and moreparticularly to systems and methods utilizing fiber optics formonitoring wellbore parameters, formation parameters, drillingoperations, condition of downhole tools installed in the wellbores orused for drilling such wellbores, for monitoring reservoirs and formonitoring of remedial work.

2. Background of the Art

A variety of techniques have been utilized for monitoring reservoirconditions, estimation and quantities of hydrocarbons (oil and gas) inearth formations, for determination formation and wellbore parametersand form determining the operating or physical condition of downholetools.

Reservoir monitoring typically involves determining certain downholeparameters in producing wellbores, such as temperature and pressureplaced at various locations in the producing wellbore, frequently overextended time periods. Wireline tools are most commonly utilized toobtain such measurements, which involves shutting down the productionfor extended time periods to determine pressure and temperaturegradients over time.

Seismic methods wherein a plurality of sensors are placed on the earth=ssurface and a source placed at the surface or downhole are utilized toobtain seismic data which is then used to update prior three dimensional(3-D″) seismic maps. Three dimensional maps updated over time aresometimes referred to as “4-D” seismic maps. The 4-D maps provide usefulinformation about reservoirs and subsurface structure. These seismicmethods are very expensive. The wireline methods are utilized at greattime intervals, thereby not providing continuous information about thewellbore conditions or that of the surrounding formations.

Permanent sensors, such as temperature sensors, pressure sensors,accelerometers or hydrophones have been placed in the wellbores toobtain continuous information for monitoring wellbores and thereservoir. Typically, a separate sensor is utilized for each type ofparameter to be determined. To obtain such measurements from usefulsegments of each wellbore, which may contain multilateral wellbores,requires using a large number of sensors, which require a large amountof power, data acquisition equipment and relatively large amount ofspace, which in many cases is impractical or cost prohibitive.

In production wells, chemicals are often injected downhole to treat theproducing fluids. However, it can be difficult to monitor and controlsuch chemical injection in real time. Similarly, chemicals are typicallyused at the surface to treat the produced hydrocarbons (i.e. break downemulsions) and to inhibit corrosion. However, it can be difficult tomonitor and control such treatment in real time.

Formation parameters are most commonly measured bymeasurement-while-drilling tools during the drilling of the wellboresand by wireline methods after the wellbores have been drilled. Theconventional formation evaluation sensors are complex and large in sizeand thus require large tools. Additionally such sensors are veryexpensive.

Prior art is also very deficient in providing suitable system andmethods for monitoring the condition or health of downhole tools. Toolconditions should be monitored during the drilling process, as the toolsare deployed in the wellbore and after deployment, whether during thecompletion phase or the production phase.

The present invention addresses some of the above-described priordeficiencies and provides systems and methods which utilize a variety offiber optic sensors for monitoring wellbore parameters, formationparameters, drilling operations, condition of downhole tools installedin the wellbores or used for drilling such wellbores, for monitoringreservoirs and for monitoring of remedial work. In some applications,the same sensor is configured to provide more than one measurement. inmany instances these sensors are relatively, consume less power and canoperate at higher temperatures than the conventional sensors.

SUMMARY OF THE INVENTION

The present invention provides fiber optics based systems and methodsfor monitoring downhole parameters and the condition and operation ofdownhole tools. The sensors may be permanently disposed downhole. Thelight source for the fiber optic sensors may be disposed in the wellboreor at the surface. The measurements from such sensors may be processeddownhole and/or at the surface. Data may also be stored for use forprocessing. Certain sensors may be configured to provide multiplemeasurements. The measurements made by the fiber optic sensors in thepresent invention include temperature, pressure, flow, liquid level,displacement, vibration, rotation, acceleration, acoustic velocity,chemical species, acoustic field, electric field, radiation, pH,humidity, electrical field, magnetic field, corrosion and density.

In one system, a plurality of spaced apart fiber optic sensors aredisposed in the wellbore to take the desired measurements. The lightsource and the processor may be disposed in the wellbore or at thesurface. Two way communication between the sensors and the processor isprovided via fiber optic links or by conventional methods. A singlelight source may be utilized in the multilateral wellboreconfigurations. The sensors may be permanently installed in thewellbores during the completion or production phases. The sensorspreferably provide measurements of temperature, pressure and flow formonitoring the wellbore production and for performing reservoiranalysis.

In another system the fiber optic sensors are deployed in a productionwellbore to monitor the injection operations, fracturing and faults.Such sensors may also be utilized in the injection well. Controllers areprovided to control the injection operation in response to the in-situor real time measurements.

In another system, the fiber optic sensors are used to determineacoustic properties of the formations including acoustic velocity andtravel time. These parameters are preferably compensated for the effectsof temperature utilizing the downhole temperature sensor measurements.Acoustic measurements are use for cross-well tomography and for updatingpreexisting seismic data or maps.

The distributed sensors of this invention find particular utility in themonitoring and control of various chemicals which are injected into thewell. Such chemicals are injected downhole to address a large number ofknown problems such as for scale inhibition and for the pretreatment ofthe fluid being produced. In accordance with the present invention, achemical injection monitoring and control system includes the placementof one or more sensors downhole in the producing zone for measuring thechemical properties of the produced fluid as well as for measuring otherdownhole parameters of interest. These sensors are preferably fiberoptic based and are formed from a sol gel matrix and provide a hightemperature, reliable and relatively inexpensive indicator of thedesired chemical parameter. The downhole chemical sensors may beassociated with a network of distributed fiber optic sensors positionedalong the wellbore for measuring pressure, temperature and/or flow.Surface and/or downhole controllers receive input from the severaldownhole sensors, and in response thereto, control the injection ofchemicals into the brothel.

The chemical parameters are preferably measured in real time and on-lineand then used to control the amount and timing of the injection of thechemicals into the wellbore or for controlling a surface chemicaltreatment system.

An optical spectrometer may be used downhole to determine the propertiesof downhole fluid. The spectrometer includes a quartz probe in contactwith the fluid. Optical energy provided to the probe, preferably from adownhole source. The fluid properties such as the density, amount ofoil, water, gas and solid contents affect the refraction of the light.The refracted light is analyzed to determine the fluid properties. Thespectrometer may be permanently installed downhole.

The fiber optic sensors are also utilized to measure formationproperties, including resistivity, formation acoustic velocity. Othermeasurements may include electric field, radiation and magnetic field.Such measurements may be made with sensors installed or placed in thewellbore for monitoring the desired formation parameters. Such sensorsare also placed in the drill string, particularly in the bottom holeassembly to provide the desired measurements during the drilling of thewellbore.

In another system, the fiber optic sensors are used to monitor thehealth or physical condition and/or the operation of the downhole tools.The measurements made to monitor the tools include one or more of (a)vibration, (b) noise (c) strain (d) stress (e) displacement (f) flowrate (g) mechanical integrity (h) corrosion (i) erosion k) scale (k)paraffin and (1) hydrate.

Examples of the more important features of the invention have beensummarized rather broadly in order that the detailed description thereofthat follows may be better understood, and in order that thecontributions to the art maybe appreciated. There are, of course,additional features of the invention that will be described hereinafterand which will form the subject of the claims appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present invention, reference shouldbe made to the following detailed description of the preferredembodiments, taken in conjunction with the accompanying drawings, inwhich like elements have been given like numerals, wherein:

FIG. 1 shows a schematic illustration of a multilateral wellbore systemand placement of fiber optic sensors according to one embodiment of thepresent invention.

FIG. 2 shows a schematic illustration of a configurations of wellboresusing fiber-optic sensor arrangements according to the present inventionto: (a) to detect and monitor compressive stresses exerted on wellborecasings and formations; (b) determine the effectiveness of the injectionprocess and in-situ control of the injection operations, and (c) makeacoustic measurements for cross-well tomography and to generate and/orupdate subsurface seismic maps.

FIG. 3 is a schematic illustrating both an injection well and aproduction well having sensors and flood front running between the wellsand loss through unintended fracturing.

FIG. 4 is a schematic representation wherein the production wells arelocated on either side of the injection well.

FIG. 5 is a schematic illustration of a chemical injection monitoringand control system utilizing a distributed sensor arrangement anddownhole chemical monitoring sensor system in accordance with oneembodiment of the present invention;

FIG. 6 is a schematic illustration of a fiber optic sensor system formonitoring chemical properties of produced fluids;

FIG. 7 is a schematic illustration of a fiber optic sol gel indicatorprobe for use with the sensor system of FIG. 6;

FIG. 8 is a schematic illustration of a surface treatment system inaccordance with the present invention; and

FIG. 9 is a schematic of a control and monitoring system for the surfacetreatment system of FIG. 8.

FIG. 10 is a schematic illustration of a wellbore system wherein a fluidconduit along a string placed in the wellbore is utilized for activatinga hydraulically-operated device and for monitoring downhole parametersusing fiber optic sensors along its length.

FIG. 11 shows a schematic diagram of a producing well wherein a fiberoptic cable with sensors is utilized to determine the condition orhealth of downhole devices and to make measurements downhole relating tosuch devices and other downhole parameters.

FIG. 12 is a schematic illustration of a wellbore system whereinelectric power is generated downhole utilizing a light cell for use inoperating sensors and devices downhole.

FIG. 13 is a schematic illustration of a wellbore system wherein apermanently installed electrically-operated device is monitored andoperated by a fiber optic based system.

FIGS. 14A and 14B show a method to avoid drilling wellbores too close toor into each other from a common platform utilizing Fiber optic sensorin the drilling string.

FIG. 14C is schematic illustration of a bottomhole assembly for use indrilling wellbores that utilizes with a number of fiber-optic sensorsfor measuring various downhole parameters during drilling of thewellbores.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

FIG. 1 shows an exemplary main or primary wellbore 12 formed from thesurface 14 and lateral wellbores 16 and 18 formed from the main wellbore18. For the purpose of explanation, and not as any limitation, the mainwellbore 12 is partly formed in a producing formation or pay zone I andpartly in a non-producing formation or dry formation II The lateralwellbore 16 extends from the main wellbore 12 at a juncture 24 into asecond producing formation III. For the purposes of illustration, thewellbores herein are shown drilled from land, however, this invention isequally applicable to offshore wellbores. It should be noted that allwellbore configurations shown and described herein are to illustrate theconcepts of present invention and shall not be construed to limit theinventions claimed herein.

In one application, a number of fiber optic sensors 40 are place in thewellbore 12. A single or a plurality of fiber optic sensors 40 may beused so as to install the desired number of fiber optic sensors 40 inthe wellbore 12. As an example, FIG. 1 shows two serially coupled fiberoptic segments 41 a and 41 b, each containing a plurality of spacedapart fiber optic sensors 40. A light source and detector (LS) 46 acoupled to an end 49 of the segment 41 a is disposed in the wellbore 12to transmit light energy to the sensors 40 and to receive the reflectedlight energy from the sensors 40. A data acquisition and processing unit(TDA) 48 a (also referred to herein as a “processor” or “controller”)may be disposed downhole to control the operation of the sensors 40, toprocess downhole sensor signals and data, and to communicate with otherequipment and devices, including devices in the wellbores or at thesurface (not shown).

Alternatively, a light source 46 b and/or the data acquisition andprocessing unit 48 b may be place at the surface 14. Similarly, fiberoptic sensor strings 45 may be disposed in other wellbores in thesystem, such as wellbores 16 and wellbore 18. A single light source,such as the light source 46 a or 46 b may be utilized for all fiberoptic sensors in the various wellbores, such as shown by dotted line 70.Alternatively, multiple light sources and data acquisition units may beused downhole, at the surface or in combination. Since the same sensormay make different types of measurements, the data acquisition unit 48 aor 48 is programmed to multiplex the measurement. Also different typesof sensors may be multiplexed as required. Multiplexing techniques areknow in the art and are thus not described in detail herein. The dataacquisition unit 46 a may be programmed to control the downhole sensors40 autonomously or upon receiving command signals from the surface or acombination of these methods.

The sensors 40 may be installed in the wellbores 12, 16, and 18 beforeor after installing casings in wellbores, such as casing 52 showninstalled in the wellbore 12. This may be accomplished by connecting thestrings 41 a and 41 b along the inside of the casing 52. In one method,the strings 41 a and 41 b may be deployed or installed by roboticsdevices (not shown). The robotics device would move the sensor strings41 a and 41 b within the wellbore 12 to the desired location and installthem according to programmed instructions provided to the roboticsdevice. The robotics device may also be utilized to replace a sensor,conduct repairs retrieve the sensors or strings to the surface andmonitor the operation of downhole sensors or devices and gather data.Alternatively, the fiber optic sensors 40 maybe placed in the casing 52(inside, wrapped around, or in the casing wall) at the surface whileindividual casing sections (which are typically about forty-foot long)are joined prior to conveying the casing sections into the borehole.Stabbing techniques for joining casing or tubing sections are known inthe art and are preferred over rotational joints because stabbinggenerally provides better alignment of the end couplings 42 and alsobecause it allows operators to test and inspect optical connectionsbetween segments for proper two-way transmission of light energy throughthe entire string 41. For coiled tubing applications, the sensors may bewrapped on the outside or placed in conduit inside the tubing. Lightsources and data acquisition unit may also be placed in the coiledtubing prior to or after deployment.

Thus, in the system described in FIG. 1, a plurality of fiber opticsensors 40 are installed spaced apart in one or more wellbores, such aswellbores 12, 16 and 18. If desired, each fiber optic sensor 40 can beconfigured to operate in more than one mode to provide a number ofdifferent measurements. The light source 46 a, and data detection andacquisition system 48 a may be placed downhole or at the surface.Although each fiber optic sensor 40 may provide measurements formultiple parameters, such sensors are still relatively small compared toindividual commonly used single measurement sensors, such as pressuresensors, stain gauges, temperature sensors, flow measurement devices andacoustic sensors. This enables making a large number of different typesof measurements utilizing relatively small downhole space. Installingdata acquisition and processing devices or units 48 a downhole allowsmaking a large number of data computations and processing downhole,avoiding the need of transmitting large amounts of data to the surface.Installing the light source 46 a downhole allows locating the source 46a close to the sensors 40, which avoids transmitting light to greatdistances from the surface thus avoiding loss of light energy. The datafrom the downhole acquisition system 48 a may be transmitted to thesurface by any suitable communication links or method including opticalfibers, wire connections, electromagnetic telemetry and acousticmethods. Data and signals may be transmitted downhole using the samecommunication links. Still in some applications, it may be desirable tolocate the light source 46 b and/or the data acquisition and processingsystem 48 b at the surface. Also, in some cases, it may be moreadvantageous to partially process data downhole and partially at thesurface.

In the present invention, the fiber optic sensors 40 may be configuredto provide measurements for temperature, pressure, flow, liquid leveldisplacement, vibration, rotation, acceleration, velocity, chemicalspecies, radiation, pH, humidity, electric fields, acoustic fields andmagnetic fields.

Still referring to FIG. 1, any number of conventional sensors, generallydenoted herein by numeral 60, may be disposed in any of the wellbores12, 16 and 18. Such sensors may include sensors for determiningresistivity of fluids and formations, gamma rays sensors andhydrophones. The measurements from the fiber optic sensors 40 andsensors 60 may be combined to determine the various conditions downhole.For example flow measurements from fiber optic sensors and theresistivity measurements from conventional sensors may be combined todetermine water saturation or to determine the oil, gas an watercontent. Alternatively, the fiber optic sensors may be utilized todetermine the same parameters.

In one mode, the fiber optic sensors are permanently installed in thewellbores at selected locations. In a producing wellbore, the sensorscontinuously or periodically (as programmed) provide the pressure and/ortemperature and/or fluid flow measurements. Such measurements arepreferably made for each producing zone in each of the wellbores. Toperform certain types of reservoir analysis, it is required to know thetemperature and pressure build rates in the wellbores. This requiresmeasuring the temperature and pressure at selected locations downholeover extended time period after shutting down the well at the surface.In the prior art methods, the well is shut down at the surface, awireline tool is conveyed in to the wellbore and positioned at onelocation in the wellbore. The tool continuously measure temperature andpressure and may provide other measurements, such as flow control. Thesemeasurements are then utilized to perform reservoir analysis, which mayinclude determining the extent of the hydrocarbon reserves remaining ina field, flow characteristics of the fluid from the producingformations, water content, etc.

The above-described prior art methods do not provide continuousmeasurements while the well is producing and requires special wirelinetools that must be conveyed downhole. The present invention, on theother hand, provides in-situ measurements while the wellbore isproducing. The fluid flow information from each zone is used todetermine the effectiveness of each producing zone. Decreasing flowrates over time may indicate problems with the flow control devices,such as screens and sliding sleeves, or clogging of the perforations androck matrix near the wellbore. This information is used to determine thecourse of action, which may include further opening or closing slidingsleeves to increase or decrease the production rate, remedial work, suchas cleaning or reaming operations, shutting down a particular zone, etc.The temperature and pressure measurements are used to continuallymonitor each production zone and to update reservoir models. To makemeasurement for determining the temperature and pressure buildup rates,the wellbores are shut down and making of measurements continues. Thisdoes not require transporting wireline tools to the location, which canbe very expensive for offshore wellbores and wellbores drilled in remotelocations. Further, the in-situ measurements and computed data can becommunicated to a central office or to the offices of log and reservoirengineers via satellite. This continuous monitoring of wellbores allowstaking relatively quick action, which can significantly improve thehydrocarbon production from the wellbores. The above describedmeasurements may also be taken for non-producing zones, such as zone II,to aid in reservoir modeling, to determine the effect of production fromvarious wellbores on the field in which the wellbores are drilled.Optical spectrometers, as described later may be used to determine theconstituents of the formation fluid and certain chemical properties ofsuch fluids. Presence of gas may be detected to prevent blow-outs or totake other actions.

FIG. 2 shows a plurality of wellbores 102, 104 and 106 formed in a field101 from the earth=s surface 110. The wellbores in FIG. 2 are configuredto describe the use of the fiber-optic sensor arrangements according tothe present invention to: (a) detect compressive stresses exerted intowellbore casings due to depletion of hydrocarbons or other geologicalphenomena; (b) determine the effectiveness of injection operations andfor in-situ monitoring and control of such operations, and (c) makeacoustic measurements for cross-well tomography and to generate and/orupdate subsurface seismic maps.

As an example only, and not as any limitation, FIG. 2 shows threewellbores 102, 104 and 106 formed in a common field or region ofinterest 101. For the purpose of illustration, the wellbores 102, 104and 106 are shown lined with respective casings 103, 105 and 107.Wellbore 102 contains a string 122 of fiber-optic sensors 40. Thesignals and data between the downhole sensor strings 122 and the surface110 are communicated via a two-way telemetry link 126. The casing 103may be made by coupling or joining tubulars or casing sections at thesurface prior to their insertion into the wellbore 102. The casingjoints are shown by numerals 120 a-n, which as indicated are typicallyabout forty (40) feet apart. Coiled tubing may also be used as thecasing.

The wellbore 102 has a production zone 130 from which hydrocarbons areproduced via perforations 132 made in the casing 103. The productionzone 130 depletes as the fluid flows from the production zone 130 intothe wellbore 102. If the production rate is high, the rate of fluiddepletion in the formations surrounding the production zone 130 may begreater than the rate at which fluids can migrate into the formation tofill the depleted pores. The weight of the formation 138 above theproduction zone exerts pressure 134 on the zone 130. If the pressure 134is grater than what the rock matrix of the zone 130 can support, itstarts to collapse, thereby exerting compressive stress on the casing103. If the compressive stress is excessive, the casing 103 may break atone or more of the casing joints 102 a-n. In case of the coiled tubing,it may buckle or collapse due to stresses. The stresses can also occurdue to natural geological changes, such as shifting of the subsurfacestrata or due to deletion by other wells in the field 101.

To detect compressive stresses in the casing 103, the fiber opticsensors 40 may be operated in the mode that provides strain gauge typeof measurements, which are then utilized to determine the extent of thecompressive stress on the casing 103. Since the sensor string 122 spansseveral joints, the system can be used to determine the location of thegreatest stress in the casing 103 and the stress distribution along anydesired section of the casing 103. This information may be obtainedperiodically or continuously during the life of the wellbore 102. Suchmonitoring of stresses provides early warning about the casing health orphysical condition and the condition of the zone 130. This informationallows the operator of the wellbore 102 to either decrease theproduction from the wellbore 102 or to shut down the well bore 102 andtake remedial measures to correct the problem.

The use of the fiber optic sensors to determine the effectiveness ofremedial operations, such as fracturing or injection, will be describedwhile referring to wellbores 104 and 106 of FIG. 2. Wellbore 104 isshown located at a distance “d₁” from the wellbore 102 and the wellbore106 at a distance “d₂” from the wellbore 104. A string 124 containing anumber of spaced apart fiber-optic sensors 40 is disposed in thewellbore 104. The length of the string 124 and the number of sensors 40and their spacing depends upon the specific application. The signals anddata between the string 124 and a surface equipment 151 are communicatedover a two-way telemetry or communications link 128.

For the purpose of illustration and not as any limitation, the wellbore106 will be utilized for injection purposes. The wellbore 106 containsperforated zone 160. The wellbore is plugged by a packer or any othersuitable device 164 below the perforations to prevent fluid flow beyondor downhole of the packer 164. To perform an injection operation, suchas for fracturing the formation around the wellbore 106 or to stimulatethe production from other wellbores in the field 101, such as thewellbore 104, a suitable fluid 166 (such as steam) migrates toward thewellbore 104 and may create a fluid wall 107 a. This causes the pressureacross the wellbore 104 and fluid flow from the formation 180 into thewellbore 104 may increase. Fracturing of the formation 180 into thewellbore 104 may increase. Additionally, the fracturing of the formation180 generates seismic waves, which generate acoustic energy. The fiberoptic sensors 40 along with any other desired sensors disposed in thewellbore 104 measure the changes in the pressure, temperature, fluidflow, acoustic signals along the wellbore 104. The sensor measurements(signals) are processed to determine the effectiveness of the injectionoperations. For example, the change in pressure, fluid flow at thewellbore 104 and the time and amount of injected material can be used todetermine the effectiveness of the injection operations. Also, acousticsignals received at the wellbore provide useful information about theextent of fracturing of the rock matrix of formation 180. Also, theacoustic signals received at the wellbore provide useful informationabout the extent of fracturing of the rock matrix for the formation 100.The acoustic signal analysis is used to determine whether to increase ordecrease the pressure of the injected fluids 166 or to terminate theoperation. This method enables the operators to continuously monitor theeffect of the injection operation in one wellbore, such as the wellbore106, upon the other wellbores in the field, such as wellbore 104.

The sensor configuration shown in FIG. 2 may be utilized to mapsubsurface formations. In one method, an acoustic source (AS) 170, suchas a vibrator or an explosive charge, is activated at the surface 110.The sensors 40 in the wellbores 102 and 104 detect acoustic signalswhich travel from the source 170 to the sensors 40 through the formation180. These signals are processed by any of the methods known in the artto map the subsurface formations and/or update the existing maps, whichare typically obtained prior to drilling wellbores, such as wellbores102 and 104. Two dimensional or three dimensional seismic maps arecommonly obtained before drilling wellbores. The data obtained by theabove-described method is used to update such maps. Updating threedimensional or 3D maps over time provides what are referred to in theoil and gas industry as four dimensional or “4D” maps. These maps arethen used to determine the conditions of the reservoirs, to performreservoir modeling and to update existing reservoir models. Thesereservoir models are used to manage the oil and gas production from thevarious wellbores in the field. The acoustic data obtained above is alsoutilized for cross-well tomography. Also, the acoustic source 170 may bedisposed (activated) within one or more of the wellbores, such as shownby numeral 170 in wellbore 104. The acoustic source is moved to otherlocations, such as shown by dotted box 170 to take additionalmeasurements. The fiber optic sensors described herein may bepermanently deployed in the wellbores.

In another embodiment of the invention relating to fracturing,illustrated schematically in FIG. 3, downhole sensors measure straininduced in the formation by the injected fluid. Strain is an importantparameter for avoiding exceeding the formation parting pressure orfracture pressure of the formation with the injected fluid. By avoidingthe opening of or widening of natural pre-existing fractures largeunswept areas of the reservoir can be avoided. The reason thisinformation is important in the regulation of pressure of the fluid toavoid such activity is that when pressure opens fractures or newfractures are created there is a path of much less resistance for thefluid to run through. Since the injection fluid will follow along thepath of least resistance it would generally run in the fractures andaround areas of the reservoir that need to be swept. This substantiallyreduces its efficiency. The situation is generally referred to in theart as an artificially high permeability channel. Another detriment tosuch a condition is the uncontrolled loss of injected fluids. Thisresults in loss of oil due to the reduced efficiency of the sweep andadditionally may function as an economic drain due to the loss ofexpensive fluids.

FIG. 3 schematically illustrates the embodiment and the condition setforth above by illustrating an injection well 250 and a production well260. Fluid 252 is illustrated escaping via the unintended fracture fromthe formation 254 into the overlying gas cap level 256 and theunderlying water table 261. The condition is avoided by the invention byusing pressure sensors to limit the injection fluid pressure asdescribed above. The rest of the fluid 252 is progressing as it isintended to through the formation 254. In order to easily and reliablydetermine what the stress is in the formation 54, fiber optic acousticsensors 256 are located in the injection well 250 at various pointstherein. The acoustic sensors 256 pick up sounds generated by stress inthe formation which propagate through the reservoir fluids or reservoirmatrix to the injection well. In general, higher sound levels wouldindicate severe stress in the formation and should generate a reductionin pressure of the injected fluid whether by automatic control or bytechnician control. A data acquisition system 258 is preferable torender the system extremely reliable and system 258 may be at thesurface where it is illustrated in the schematic drawing or may bedownhole. Based upon acoustic signals received the system of theinvention, preferably automatically, although manually is workable,reduces pressure of the injected fluid by reducing pump pressure.Maximum sweep efficiency is thus obtained.

In yet another embodiment of the invention, as schematically illustratedin FIG. 4, acoustic generators and receivers are employed to determinewhether a formation which is bifurcated by a fault is sealed along thefault or is permeable along the fault. It is known by one of ordinaryskill in the art that different strata within a formation bifurcated bya fault may have some zones that flow and some zones that are sealed;this is the illustration of FIG. 4. Referring directly to FIG. 4,injection well 270 employs a plurality of fiber optic sensors 272 andacoustic generators 274 which, most preferably, alternate withincreasing depth in the wellbore. In production well 280, a similararrangement of sensors 272 and acoustic generators 274 are positioned.The sensors and generators are preferably connected to processors whichare either downhole or on the surface and preferably also connect to theassociated production or injection well. The sensors 272 can receiveacoustic signals that are naturally generated in the formation,generated by virtue of the fluid flowing through the formation from theinjection well and to the production well and also can receive signalswhich are generated by signal generators 274. Where signal generators274 generate signals, the reflected signals that are received by sensors272 over a period of time can indicate the distance and acoustic volumethrough which the acoustic signals have traveled. This is illustrated inarea A of FIG. 4 in that the fault line 275 is sealed between area A andarea B on the figure. This is illustrated for purposes of clarity onlyby providing circles 276 along fault line 275. The areas of fault line275 which are permeable are indicated by hash marks 277 through faultline 275. Since the acoustic signal represented by arrows andsemi-curves and indicated by numeral 278 cannot propagate through thearea C which bifurcates area A from area B on the left side of thedrawing, that signal will bounce and it then can be picked up by sensor272. The time delay, number and intensity of reflections andmathematical interpretation which is common in the art provides anindication of the lack of pressure transmissivity between those twozones. Additionally this pressure transmissivity can be confirmed by thedetection by said acoustic signals by sensors 272 in the production well280. In the drawing, the area directly beneath area A, indicated as areaE, is permeable to area B through fault 275 because the region D in thatarea is permeable and will allow flow of the flood front from theinjection well 270 through fault line 275 to the production well 280.Acoustic sensors and generators can be employed here as well since theacoustic signal will travel through the area D and, therefore,reflection intensity to the receivers 272 will decrease. Time delay willincrease. Since the sensors and generators are connected to a centralprocessing unit and to one another it is a simple operation to determinethat the signal, in fact, traveled from one well to the other andindicates permeability throughout a particular zone. By processing theinformation that the acoustic generators and sensors can provide theinjection and production wells can run automatically by determiningwhere fluids can flow and thus opening and closing valves at relevantlocations on the injection well and production well in order to flushproduction fluid in a direction advantageous to run through a zone ofpermeability along the fault.

Other information can also be generated by this alternate system of theinvention since the sensors 272 are clearly capable of receiving notonly the generated acoustic signals but naturally occurring acousticwaveforms arising from both the flow of the injected fluids as theinjection well and from those arising within the reservoirs in result ofboth fluid injection operations and simultaneous drainage of thereservoir in resulting production operations. The preferred permanentdeployment status of the sensors and generators of the invention permitand see to the measurements simultaneously with ongoing injectionflooding and production operations. Advancements in both acousticmeasurement capabilities and signal processing while operating theflooding of the reservoir represents a significant, technologicaladvance in that the prior art requires cessation of theinjection/production operations in order to monitor acoustic parametersdownhole. As one of ordinary skill in the art will recognize thecessation of injection results in natural redistribution of the activeflood profile due primarily to gravity segregation of fluids andentropic phenomena that are not present during active floodingoperations. This also enhances the possibility of prematurebreakthrough, as oil migrates to the relative top of the formation andthe injected fluid, usually water, migrates to the relative bottom ofthe formation. Hence, there is a significant possibility that the waterwill actually reach the production well and thus further pumping ofsteam or water will merely run underneath the layer of oil at the top ofthe formation and the sweep of that region would be extremely difficultthereafter.

In yet another embodiment of the invention fiber optics are employed(similar to those disclosed in the U.S. application filed on Jun. 10,1997 entitled CHEMICAL INJECTION WELL CONTROL AND MONITORING SYSTEMunder Attorney docket number 97-1554 and BHI 197-09539-US which is fullyincorporated herein by reference) to determine the amount of and/orpresence of biofouling within the reservoir by providing a culturechamber within the injection or production well, wherein light of apredetermined wavelength may be injected by a fiber optical cable,irradiating a sample determining the degree to which biofouling may haveoccurred. As one of ordinary skill in the art will recognize, variousbiofouling organisms will have the ability to fluoresce at a givenwavelength, that wavelength once determined, is useful for the purposeabove stated.

Referring back to FIG. 2, the flood front may also be monitored from the“back” employing sensors 155 installed in the injection well 106. Thesesensors provide acoustic signals which reflect from the water/oilinterface thus providing an accurate picture in a moment in time of thethree-dimensional flood front. Taking real time 4D pictures provides anaccurate format of the density profile of the formation due to theadvancing flood front. Thus, a particular profile and the relativeadvancement of the front can be accurately determined by the densityprofile changes. It is certainly possible to limit the sensors andacoustic generators to the injection well for such a system. However, itis generally more preferable to also introduce sensors and acousticgenerators in the production well toward which the front is moving (asdescribed before) thus allowing an immediate double check of the fluidfront profile. That is, acoustic generators on the production well willreflect a signal off the oil/water interface and will provide an equallyaccurate three-dimensional fluid front indicator. The indicators fromboth sides of the front should agree and thus provides an extremelyreliable indication of location and profile. A common processor 151 maybe used for processing data from the wells 102-106.

Referring now to FIG. 5, the distributed fiber optic sensors of the typedescribed above are also well suited for use in a production well wherechemicals are being injected therein and there is a resultant need forthe monitoring of such a chemical injection process so as to optimizethe use and effect of the injected chemicals. Chemicals often need to bepumped down a production well for inhibiting scale, paraffins and thelike as well as for other known processing applications and pretreatmentof the fluids being produced. Often, as shown in FIG. 5, chemicals areintroduced in an annulus 400 between the production tubing 402 and thecasing 404 of a well 406. The chemical injection (shown schematically at408) can be accomplished in a variety of known methods such as inconnection with a submersible pump (as shown for example in U.S. Pat.No. 4,582,131, assigned to the assignee hereof and incorporated hereinby reference) or through an auxiliary line associated with a cable usedwith an electrical submersible pump (such as shown for example in U.S.Pat. No. 5,528,824, assigned to the assignee hereof and incorporatedherein by reference).

In accordance with an embodiment of the present invention, one or morebottomhole sensors 410 are located in the producing zone 405 for sensinga variety of parameters associated with the producing fluid and/orinteraction of the injected chemical and the producing fluid 407. Thus,the bottomhole sensors 410 will sense parameters relative to thechemical properties of the produced fluid such as the potential ioniccontent, the covalent content, pH level, oxygen levels, organicprecipitates and like measurements. Sensors 410 can also measurephysical properties associated with the producing fluid and/or theinteraction of the injected chemicals and producing fluid such as theoil/water cut, viscosity and percent solids. Sensors 410 can alsoprovide information related to paraffin and scale build-up, H₂S contentand the like.

Bottomhole sensors 410 preferably communicate with and/or are associatedwith a plurality of distributed sensors 412 which are positioned alongat least a portion of the wellbore (e.g., preferably the interior of theproduction tubing) for measuring pressure, temperature and/or flow rateas discussed above in connection with FIG. 1. The present invention isalso preferably associated with a surface control and monitoring system414 and one or more known surface sensors 415 for sensing parametersrelated to the produced fluid; and more particularly for sensing andmonitoring the effectiveness of treatment rendered by the injectedchemicals. The sensors 415 associated with surface system 414 can senseparameters related to the content and amount of, for example, hydrogensulfide, hydrates, paraffins, water, solids and gas.

Preferably, the production well disclosed in FIG. 5 has associatedtherewith a so-called Aintelligent@ downhole control and monitoringsystem which may include a downhole computerized controller 418 and/orthe aforementioned surface control and monitoring system 414. Thiscontrol and monitoring system is of the type disclosed in U.S. Pat. No.5,597,042, which is assigned to the assignee hereof and fullyincorporated herein by reference. As disclosed in U.S. Pat. No.5,597,042, the sensors in the “intelligent” production wells of thistype are associated with downhole computer and/or surface controllerswhich receive information from the sensors and based on thisinformation, initiate some type of control for enhancing or optimizingthe efficiency of production of the well or in some other way effectingthe production of fluids from the formation. In the present invention,the surface and/or downhole computers 414, 418 will monitor theeffectiveness of the treatment of the injected chemicals and based onthe sensed information, the control computer will initiate some changein the manner, amount or type of chemical being injected. In the systemof the present invention, the sensors 410 and 412 may be connectedremotely or in-situ.

In a preferred embodiment of the present invention, the bottomholesensors comprise fiber optic chemical sensors. Such fiber optic chemicalsensors preferably utilize fiber optic probes which are used as a sampleinterface to allow light from the fiber optic to interact with theliquid or gas stream and return to a spectrometer for measurement. Theprobes are typically composed of sol gel indicators. Sol gel indicatorsallow for on-line, real time measurement and control through the use ofindicator materials trapped in a porous, sol gel derived, glass matrix.Thin films of this material are coated onto optical components ofvarious probe designs to create sensors for process and environmentalmeasurements. These probes provide increased sensitivity to chemicalspecies based upon characteristics of the specific indicator. Forexample, sol gel probes can measure with great accuracy the pH of amaterial and sol gel probes can also measure for specific chemicalcontent. The sol gel matrix is porous, and the size of the pores isdetermined by how the glass is prepared. The sol gel process can becontrolled so as to create a sol gel indicator composite with poressmall enough to trap an indicator in the matrix but large enough toallow ions of a particular chemical of interest to pass freely in andout and react with the indicator. An example of suitable sol gelindicator for use in the present invention is shown in FIGS. 6 and 7.

Referring to FIGS. 6 and 7, a probe is shown at 416 connected to a fiberoptic cable 418 which is in turn connected both to a light source 420and a spectrometer 422. As shown in FIG. 7, probe 416 includes a sensorhousing 424 connected to a lens 426. Lens 426 has a sol gel coating 428thereon which is tailored to measure a specific downhole parameter suchas pH or is selected to detect the presence, absence or amount of aparticular chemical such as oxygen, H₂S or the like. Attached to andspaced from lens 426 is a mirror 430. During use, light from the fiberoptic cable 418 is collimated by lens 426 whereupon the light passesthrough the sol gel coating 428 and sample space 432. The light is thenreflected by mirror 430 and returned to the fiber optical cable. Lighttransmitted by the fiber optic cable is measured by the spectrometer422. Spectrometer 422 (as well as light source 420) may be locatedeither at the surface or at some location downhole. Based on thespectrometer measurements, a control computer 414, 416 will analyze themeasurement and based on this analysis, the chemical injection apparatus408 will change the amount (dosage and concentration), rate or type ofchemical being injected downhole into the well. Information from thechemical injection apparatus relating to amount of chemical left instorage, chemical quality level and the like will also be sent to thecontrol computers. The control computer may also base its controldecision on input received from surface sensor 415 relating to theeffectiveness of the chemical treatment on the produced fluid, thepresence and concentration of any impurities or undesired by-productsand the like.

Alternatively a spectrometer may be utilized to monitor certainproperties of downhole fluids. The sensor includes a glass or quartzprobe, one end or tip of which is placed in contact with the fluid.Light supplied to the probe is refracted based on the properties of thefluid. Spectrum analysis of the refracted light is used to determine theand monitor the properties, which include the water, gas, oil and solidcontents and the density.

In addition to the bottomhole sensors 410 being comprised of the fiberoptic sol gel type sensors, distributed sensors 412 along productiontubing 402 may also include the fiber optic chemical sensors of the typediscussed above. In this way, the chemical content of the productionfluid may be monitored as it travels up the production tubing if that isdesirable.

The permanent placement of the sensors 410, 412 and control system 417downhole in the well leads to a significant advance in the field andallows for real time, remote control of chemical injections into a wellwithout the need for wireline device or other well interventions.

In accordance with the present invention, a novel control and monitoringsystem is provided for use in connection with a treating system forhandling produced hydrocarbons in an oilfield. Referring to FIG. 8, atypical surface treatment system used for treating produced fluid in oilfields is shown. As is well known, the fluid produced from the wellincludes a combination of emulsion, oil, gas and water. After these wellfluids are produced to the surface, they are contained in a pipelineknown as a “flow line”. The flow line can range in length from a fewfeet to several thousand feet. Typically, the flow line is connecteddirectly into a series of tanks and treatment devices which are intendedto provide separation of the water in emulsion from the oil and gas. Inaddition, it is intended that the oil and gas be separated for transportto the refinery.

The produced fluids flowing in the flow line and the various separationtechniques which act on these produced fluids lead to serious corrosionproblems. Presently, measurement of the rate of corrosion on the variousmetal components of the treatment systems such as the piping and tanksis accomplished by a number of sensor techniques including weight losscoupons, electrical resistance probes, electrochemical—linearpolarization techniques, electrochemical noise techniques and ACimpedance techniques. While these sensors are useful in measuring thecorrosion rate of a metal vessel or pipework, these sensors do notprovide any information relative to the chemicals themselves, that isthe concentration, characterization or other parameters of chemicalsintroduced into the treatment system. These chemicals are introduced fora variety of reasons including corrosion inhibition and emulsionbreakdown, as well as scale, wax, asphaltene, bacteria and hydratecontrol.

In accordance with an important feature of the present invention,sensors are used in chemical treatment systems of the type disclosed inFIG. 8 which monitors the chemicals themselves as opposed to the effectsof the chemicals (for example, the rate of corrosion). Such sensorsprovide the operator of the treatment system with a real timeunderstanding of the amount of chemical being introduced, the transportof that chemical throughout the system, the concentration of thechemical in the system and like parameters. Examples of suitable sensorswhich may be used to detect parameters relating to the chemicals in thetreatment system include the fiber optic sensor described above withreference to FIGS. 6 and 7. Ultrasonic absorption and reflection,laser-heated cavity spectroscopy (LIMS), X-ray fluorescencespectroscopy, neutron activation spectroscopy, pressure measurement,microwave or millimeter wave radar reflectance or absorption, and otheroptical and acoustic (i.e., ultrasonic or sonar) methods may also beused. A suitable microwave sensor for sensing moisture and otherconstituents in the solid and liquid phase influent and effluent streamsis described in U.S. Pat. No. 5,455,516, all of the contents of whichare incorporated herein by reference. An example of a suitable apparatusfor sensing using LIBS is disclosed in U.S. Pat. No. 5,379,103 all ofthe contents of which are incorporated herein by reference. An exampleof a suitable apparatus for sensing LIMS is the LASMA Laser MassAnalyzer available from Advanced Power Technologies, Inc. of Washington,D.C. An example of a suitable ultrasonic sensor is disclosed in U.S.Pat. No. 5,148,700 (all of the contents of which are incorporated hereinby reference). A suitable commercially available acoustic sensor is soldby Entech Design, Inc., of Denton, Tex. under the trademark MAPS⁷.Preferably, the sensor is operated at a multiplicity of frequencies andsignal strengths. Suitable millimeter wave radar techniques used inconjunction with the present invention are described in chapter 15 ofPrinciples and Applications of Millimeter Wave Radar, edited by N. C.Currie and C. E. Brown, Artech House, Norwood, Mass. 1987.

While the sensors may be utilized in a system such as shown in FIG. 8 ata variety of locations, the arrows numbered 500, through 516 indicatethose positions where information relative to the chemical introductionwould be especially useful.

Referring now to FIG. 9, the surface treatment system of FIG. 8 is showngenerally at 520. In accordance with the present invention, the chemicalsensors (i.e. 500-516) will sense, in real time, parameters (i.e.,concentration and classification) related to the introduced chemicalsand supply that sensed information to a controller 522 (preferably acomputer or microprocessor based controller). Based on that sensedinformation monitored by controller 522, the controller will instruct apump or other metering device 524 to maintain, vary or otherwise alterthe amount of chemical and/or type of chemical being added to thesurface treatment system 520. The supplied chemical from tanks 526 can,of course, comprise any suitable treatment chemical such as thosechemicals used to treat corrosion, break down emulsions, etc. Examplesof suitable corrosion inhibitors include long chain amines oraminodiazolines. Suitable commercially available chemicals includeCronoxÔ which is a corrosion inhibitor sold by Baker Petrolite, adivision of Baker-Hughes Incorporated, of Houston, Tex.

Thus, in accordance with the control and monitoring system of FIG. 9,based on information provided by the chemical sensors 500-516,corrective measures can be taken for varying the injection of thechemical (corrosion inhibitor, emulsion breakers, etc.) into the system.The injection point of these chemicals could be anywhere upstream of thelocation being sensed such as the location where the corrosion is beingsensed. Of course, this injection point could include injectionsdownhole. In the context of a corrosion inhibitor, the inhibitors workby forming a protective film on the metal and thereby prevent water andcorrosive gases from corroding the metal surface. Other surfacetreatment chemicals include emulsion breakers which break the emulsionand facilitate water removal. In addition to removing or breakingemulsions, chemicals are also introduced to break out and/or removesolids, wax, etc. Typically, chemicals are introduced so as to providewhat is known as a base sediment and water (B.S. and W.) of less than1%.

In addition to the parameters relating to the chemical introductionbeing sensed by chemical sensors 500-516, the monitoring and controlsystem of the present invention can also utilize known corrosionmeasurement devices as well including flow rate, temperature andpressure sensors. These other sensors are schematically shown in FIG. 9at 528 and 530. The present invention thus provides a means formeasuring parameters related to the introduction of chemicals into thesystem in real time and on line. As mentioned, these parameters includechemical concentrations and may also include such chemical properties aspotential ionic content, the covalent content, pH level, oxygen levels,organic precipitates and like measurements. Similarly, oil/water cutviscosity and percent solids can be measured as well as paraffin andscale build-up, H₂S content and the like. The fiber optic sensorsdescribed above may be used to determine the above mentioned parameterdownhole.

FIG. 10 is a schematic diagram of a wellbore system 600 wherein a commonconduit is utilized for operating a downhole hydraulically-operated toolor device and for monitoring one or more downhole parameters utilizingthe fiber optics. System 600 includes a wellbore 602 having a surfacecasing 601 installed a short distance from the surface 604. After thewellbore 102 has been drilled to a desired depth. A completion orproduction string 606 is conveyed into the wellbore 602. The string 606includes at least one downhole hydraulically-operated device 614 carriedby a tubing 608 which tubing may be a drill pipe, coiled tubing orproduction tubing. A fluid conduit 610 (or hydraulic line) having adesired inner diameter 611 is placed or attached either on the outsideof the string 606 (as shown in FIG. 10) or in the inside of the stringin any suitable manner. The conduit 610 is preferably routed at adesired location on the string 606 via a u-joint 612 so as to provide asmooth transition for returning the conduit 610 to the surface 604. Ahydraulic connection 624 is provided from the conduit 610 to the device614 so that a fluid under pressure can pass from the conduit 610 to thedevice 614.

After the string 606 has been placed or installed at a desired depth inthe wellbore 602, an optical fiber 612 is pumped under pressure at theinlet 630 a from a source of fluid 630. The optical fiber 622 passesthrough the entire length of the conduit 610 and returns to the surface604 via outlet 630 b. The fiber 622 is then optically coupled to a lightsource and recorder (or detector) (LS/REC) 640. A dataacquisition/signal processor (DA/SP) 642 processes data/signal receivedvia the optical fiber 622 and also controls the operation of the lightsource and recorder 640.

The optical fiber 622 may include a plurality of sensors 620 distributedalong its length. Sensors 620 may include temperature sensors, pressuresensors, vibration sensors or any other fiber optic sensor that can beplaced on the fiber optic cable 622. Sensors 620 are formed into thecable 622 during the manufacturing of the cable 622. The downhole device614 may be any downhole fluid-activated device including but not limitedto a valve, a choke, a sliding sleeve, a perforating device, and apacker, fluid flow regulation device, or any other completion and/orproduction device. The device 614 is activated by supplying fluid underpressure through the conduit 610. In the embodiment shown herein, theline 610 receives fiber optic cable 622 throughout its length and isconnected to surface instrumentation 640 and 642 for distributedmeasurements of downhole parameters along its length. The line 610 maybe arranged downhole along the string 606 in a V or other convenientshape. Alternatively, the line 610 may terminate at the device 614and/or continue to a second device (not shown) downhole. the fiber opticsensors also may be disposed on the line in any other suitable mannersuch as wrapping them on the outside of the conduit 610. In the presentinvention, a common line is thus used to control ahydraulically-controlled device and to monitor one or more downholeparameters along the line.

During the completion of the wellbore 602, the sensors 620 provideuseful measurements relating to their associated downhole parameters andthe line 606 is used to actuate a downhole device. The sensors 620continue to provide information about the downhole parameters over time.

FIG. 11 shows a schematic diagram of a producing well 702 thatpreferably has two electric submersible pumps (AESP@) 714, one forpumping the oil/gas 706 to the surface 703 and the other to pump anyseparated water back into a formation. The formation fluid 706 flowsfrom a producing zone 708 into the wellbore 702 via perforations 707.Packers 710 a and 710 b installed below and above the ESP 714 force thefluid 706 to flow to the surface 703 via pumps ESP 714. An oil waterseparator 750 separates the oil and water and provide them to theirrespective pumps 714 a-714 b. A choke 752 provides desired backpressure. An instrument package 760 and pressure sensor is installed inthe pump string 718 to measure related parameters during production. Thepresent invention utilizes optical fiber with embedded sensors toprovide measurements of selected parameters, such as temperature,pressure, vibration, flow rate as described below. ESP=s 714 use largeamounts of electric power which is supplied from the surface via a powercable 724. Such cables often tend to corrode an/or overheated. Due tothe high power being carried by the cable 724, electrical sensors aregenerally not placed on or along side the cable 724.

In one embodiment of the present invention as shown in FIG. 11, a fiberoptic cable 722 carrying sensors 720 is placed along the power cable724. The fiber optic cable 702 may also be extended below the ESP 714 toreplace conventional sensors in the instrumentation package 760 and toprovide control signals to the downhole device or processors asdescribed earlier. In one application, the sensors 720 measure vibrationand temperature of the ESP 714. It is desirable to operate the ESP at alow temperature and without excessive vibration. The ESP 714 speed isadjusted so as to maintain one or both such parameters below theirpredetermined maximum value or within their respective predeterminedranges. The fiber optic sensors are used in this application tocontinuously or periodically determine the physical condition (health)of the ESP. The fiber optic cable 722 may be extended or deployed belowthe ESP at the time of installing the production string 718 in themanner described with respect to FIG. 10. It should be obvious that theuse of the ESP is only one example of the downhole device that can beused for the purposes of this invention. The present invention may beused to continuously measure downhole parameters, to monitor the healthor condition of downhole devices and to control downhole devices. Anysuitable device may be utilized for this purpose including, slidingsleeves, packers, flow control devices etc.

FIG. 12 shows a wellbore 802 with a production string 804 having one ormore electrically-operated or optically-operated devices, generallydenoted herein by numeral 850 and one or more downhole sensors 814. Thestring 804 includes batteries 812 which provide electrical power to thedevices 850 and sensors 814. The batteries are charged by generatingpower downhole by turbines (not shown) or by supplying power from thesurface via a cable (not shown).

In the present invention a light cell 810 is provided in the string 804which is coupled to an optical fiber 822 that has one or more sensors820 associated therewith. A light source 840 at the surface provideslight to the light cell 810 which generates electricity which chargesthe downhole batteries 812. The light cell 810 essentially tricklecharges the batteries. In many applications the downhole devices, suchas devices 850, are activated infrequently. Trickle charging thebatteries may be sufficient and thus may eliminate the use of otherpower generation devices. In applications requiring greater powerconsumption, the light cell may be used in conjunction with otherconventional power generation devices.

Alternatively, if the device 850 is optically-activated, the fiber 822is coupled to the device 850 as shown by the dotted line 822 a and isactivated by supplying optical pulses from the surface unit 810. Thus,in the configuration of FIG. 12, a fiber optics device is utilized togenerate electrical energy downhole, which is then used to charge asource, such as a battery, or operate a device. The fiber 822 is alsoused to provide two-way communication between the DA/SP 842 and downholesensors and devices.

FIG. 13 shows a schematic of a wellbore system 900 wherein a permanentlyinstalled electrically-operated device is monitored and controlled by afiber optic based system. The system 900 includes a wellbore 902 and anelectrically-operated device 904 installed at a desired depth, which maybe a sliding sleeve, a choke, a fluid flow control device, etc. Ancontrol unit 906 controls the operation of the device 904. A productiontubing 910 installed above the device 904 allows formation fluid to flowto the surface 901. During the manufacture of the string 911 thatincludes the device 904 and the tubing 910, a conduit 922 is clampedalong the length of the tubing 910 with clamps 921. An optical coupler907 is provided at the electrical control unit 906 which can mate with acoupler fed through the conduit 922.

Either prior to or after placing the string 910 in the wellbore 902, afiber optic cable 921 is deployed in the conduit 922 so that a coupler922 a at the cable 921 end would couple with the coupler 907 of thecontrol unit 906. A light source 990 provides the light energy to thefiber 922. A plurality of sensors 920 may be deployed along the fiber922 as described before. A sensor preferably provided on the fiber 922determines the flow rate of formation fluid 914 flowing through thedevice 904. Command signals are sent by DA/SP 942 to activate the device904 via the fiber 922. These signals are detected by the control unit906, which in turn operate the device 904. This, in the configuration ofFIG. 13, fiber optics is used to provide two way communication betweendownhole devices, sensors and a surface unit and to operate the downholedevices.

FIGS. 14A and 14B show a method monitoring the location of prior wellsduring drilling of a wellbore so as to avoid drilling the wellbore tooclose to or into the existing wellbores. Several wellbores are sometimesdrilled from a rig at a single location. This is a common practice inoffshore drilling because moving large platforms or rigs is notpractical. Often, thirty to forty wellbores are drilled from a singlelocation. A template is used to define the relative location of thewells at the surface. FIGS. 14A and 14B show wellbores 1004-1008 drilledfrom a common template 1005. The template 1005 shows openings 1004 a,1006 a, and 1008 a as surface locations for the wellbores 1004, 1006 and1008 respectively. Locations of all other wellbores drilled from thetemplate 1005 are referred to by numeral 1030. FIG. 14B also shows alateral or branch wellbore 1010 being drilled from the wellbore 1004, bya drill bit 1040. The wellbore 1008 is presumed to be drilled beforewellbores 1004 and 1010. For the purposes of this example, it is assumedthat the driller wishes to avoid drilling the wellbore 1010 too close toor onto the wellbore 1008. Prior to drilling the wellbore 1010, aplurality of fiber optic sensors 40 are disposed in the wellbore 1008.The vibrations of the drill bit 1040 during drilling of the wellbore1010 generate acoustic energy, which travels to the wellbore 1008 by aprocessor of the kind described earlier. The sensors 40 in the well bore1008 detect acoustic signals received at the well bore 1008. Thereceived signals are processed and analyzed to determine the distance ofthe drill bit from the wellbore 1008. The travel time of the acousticsignals from the drill bit 1040 to the sensors 40 in the wellbore 1008provides relatively accurate measure of such distance. The fiber optictemperature sensor measurements are preferably used to correct orcompensate the travel time or the underlying velocity for the effects oftemperature. The driller can utilize this information to ensure that thewellbore 1010 is being drilled at a safe distance from the wellbore1008, thereby avoiding drilling it too close or into the wellbore 1008.

The fiber optic sensors described above are especially suitable for usein drill strings utilized for drilling wellbores. For the purposes ofthis invention, a “drill string” includes a drilling assembly or bottomhole assembly (“BHA”) carried by a tubing which may be drill pipe orcoiled tubing. A drill bit is attached to the BHA which is rotated byrotating the drill pipe or by a mud motor. FIG. 14C shows a bottomholeassembly 1080 having the drill bit 1040 at one end. The bottomholeassembly 1080 is conveyed by a tubing 1062 such as a drill pipe or acoiled-tubing. A mud motor 1052 drives the drill bit 1040 attached tothe bottom hole end of the BHA. A bearing assembly 1055 coupled to thedrill bit 1040 provides lateral and axial support to the drill bit 1040.Drilling fluid 1060 passes through the drilling assembly 1080 and drivesthe mud motor 1052, which in turn rotates the drill bit 1040.

As described below, a variety of fiber optic sensors are placed in theBHA 1080, drill bit 1040 and the tubing 1082. Temperature and pressuresensors T4 and P5 are placed in the drill bit for monitoring thecondition of the drill bit 1040. Vibration and displacement sensors V1monitor the vibration of the BHA and displacement sensors V1 monitor thelateral and axial displacement of the drill shaft and that of the BHA.Sensors T1-T3 monitor the temperature of the elastomeric stator of themud motor 1052, while the sensors P1-P4 monitor differential pressureacross the mud motor, pressure of the annulus and the pressure of thefluid flowing through the BHA. Sensors V1-V2 provide measurements forthe fluid flow through the BHA and the wellbore. Additionally aspectrometric sensors Si of the type described above may be placed in asuitable section 1050 of the BHA to measure the fluid and chemicalproperties of the wellbore fluid. Fiber optic sensor R1 is used todetect radiation. Acoustic sensors S1-S2 may be placed in the BHA fordetermining the acoustic properties of the formation. Additionallysensors, generally denoted herein as S may be used to providemeasurements for resistivity, electric field, magnetic field and othermeasurements that can be made by the fiber optic sensors. A light sourceLS and the data acquisition and processing unit DA are preferablydisposed in the BHA. The processing of the signals is preferably donedownhole, but may be done at the surface. Any suitable two waycommunication method may be used to communicate between the BHA and thesurface equipment, including optical fibers. The measurements made areutilized for determining formation parameters of the kind describedearlier, fluid properties and the condition of the various components ofthe drill string including the condition of the drill bit, mud motor,bearing assembly and any other component part of the drilling assembly.

While foregoing disclosure is directed to the preferred embodiments ofthe invention, various modifications will be apparent to those skilledin the art. It is intended that all variations within the scope andspirit of the appended claims be embraced by the foregoing disclosure.

1-16. (canceled)
 17. A downhole tool monitoring system, comprising: (a)a tool in a first wellbore; and (b) at least one fiber optic sensor inthe first wellbore providing measurements for an operating parameter ofthe tool.
 18. The system of claim 17 wherein the operating parameter isone of (i) vibration, (ii) noise, (iii) strain, (iv) stress, (v)displacement, (vi) flow rate, (vii) mechanical integrity, (viii)corrosion, (ix) erosion, (x) scale, (xi) paraffin, (xii) hydrate, (xiii)displacement, (xiv) temperature, (xv) pressure, (xvi) acceleration, and,(xvii) stress.
 19. The system of claim 1 wherein the a least one fiberoptic sensor is one of (i) vibration sensor, (ii) strain sensor, (iii)chemical sensor, (iv) optical spectrometer sensor, (v) flow rate sensor,(vi) temperature sensor, and, (vii) pressure sensor.
 20. The system ofclaim 17 wherein the tool in the first wellbore is one of a flow controldevice, packer, sliding sleeve, screen, mud motor, drill bit, bottomhole assembly, coiled tubing and casing. 21-41. (canceled)
 42. Thesystem of claim 17 wherein said first wellbore comprises a mainwellbore, the system further comprising a second (lateral) wellbore. 43.The system of claim 42 wherein one of said first and second wellbores isformed in at least one of (i) a producing formation, and, (ii) anon-producing formation.
 44. The system of claim 17 wherein said atleast one fiber optic sensor comprises a plurality of fiber opticsensors.
 45. The system of claim 44 wherein said plurality of fiberoptic sensors form two serially coupled fiber optic segments.
 46. Thesystem of claim 17 further comprising a data acquisition unit forperforming a function that is at least one of (i) controlling theoperation of the at least one fiber optic sensor, (ii) processingsignals from the at least one fiber optic sensor, (iii) communicatingwith other equipment and devices located either downhole or at a surfacelocation. 47 The system of claim 46 wherein said data acquisition unitis disposed at a surface location.
 48. The system of claim 46 whereinsaid data acquisition unit is disposed at a downhole location.
 49. Thesystem of claim 46 wherein said data acquisition unit uses datamultiplexing.
 50. The system of claim 17 wherein said at least one fiberoptic sensor further comprises sensors of different types.
 51. Thesystem of claim 17 wherein the at least one fiber optic sensor isinstalled in said first wellbore before installation of a casingtherein.
 52. The system of claim 17 wherein the at least one fiber opticsensor is installed in said first wellbore after installation of casingtherein.
 53. The system of claim 17 wherein the at least one fiber opticsensor is installed in said first wellbore by a robotic device.
 54. Thesystem of claim 53 wherein said robotic device performs saidinstallation according to programmed instructions.
 55. The system ofclaim 53 wherein said robotic device performs said installation at adesired location.
 56. The system of claim 17 wherein said at least onefiber optic sensor is attached to a casing section prior to installationof casing in said first borehole.
 57. The system of claim 56 whereinsaid casing further comprises a plurality of casing sections stabbedtogether to facilitate inspection of communication through saidplurality of casing sections
 58. The system of claim 48 wherein datafrom said downhole data acquisition unit is transmitted to a surfacelocation using a method selected from (i) transmission through opticalfiber, (ii) electromagnetic transmission, (iii) acoustic transmission,and, (iv) wire connections.
 59. The system of claim 17 furthercomprising an additional sensor selected from (i) a resistivity sensor,(ii) a gamma ray sensor, and, (iii) an acoustic sensor.
 60. The systemof claim 17 wherein said at least one fiber optic sensor is permanentlyinstalled in said first wellbore.
 61. The system of claim 44 whereinsaid plurality of fiber optic sensors make measurements in one or moreproducing zones of an earth formation.
 62. The system of claim 46wherein said data acquisition unit controls the operation of said toolbased at least in part to a measurement made by said at least one fiberoptic sensor.
 63. The system of claim 62 wherein controlling theoperation of said tool is one of (i) opening a sliding sleeve, (ii)closing a sliding sleeve, (iii) increasing a production rate from aproducing earth formation, (iv) decreasing a production rate from aproducing earth formation, (v) shutting down a producing zone, (vi)performing a cleaning operation, and, (vii) performing a reamingoperation.
 64. A method of making measurements in a wellbore in an earthformation, the method comprising: (a) conveying a tool in a firstwellbore in the earth formation; and (b) using at least one fiber opticsensor in the first wellbore for providing measurements for an operatingparameter of the tool.
 65. The method of claim 64 wherein the operatingparameter is one of (i) vibration, (ii) noise (iii) strain (iv) stress(v) displacement (vi) flow rate (vii) mechanical integrity (viii)corrosion (ix) erosion (x) scale (xi) paraffin (xii) hydrate, (xiii)displacement, (xiv) temperature, (xv) pressure, (xvi) acceleration, and(xvii) stress.
 66. The method of claim 64 wherein the at least one fiberoptic sensor is one of (i) vibration sensor (ii) strain sensor (iii)chemical sensor (iv) optical spectrometer sensor and (v) flow ratesensor, (vi) temperature sensor, and (vii) pressure sensor.
 67. Thesystem of claim 64 wherein the tool in the first wellbore is one of aflow control device, packer, sliding sleeve, screen, mud motor, drillbit, bottom hole assembly, coiled tubing and casing.
 68. The method ofclaim 64 wherein said first wellbore comprises a main wellbore, themethod further comprising a using a fiber optic sensor in a second(lateral) wellbore.
 69. The method of claim 68 wherein one of said firstand second wellbores is formed in at least one of (i) a producingformation, and, (ii) a non-producing formation.
 70. The method of claim64 wherein using said at least one fiber optic sensor further comprisesusing a plurality of fiber optic sensors
 71. The method of claim 70wherein said plurality of fiber optic sensor comprises forming at leasttwo serially coupled segments from said plurality of fiber opticsensors.
 72. The method of claim 64 further comprising using a dataacquisition unit for performing a function that is at least one of (i)controlling the operation of the at least one fiber optic sensor, (ii)process signals from the at least one fiber optic sensor, (iii)communicating with other equipment and devices located either downholeor at a surface location.
 73. The method of claim 72 wherein using saiddata acquisition unit further comprises using said unit at a surfacelocation.
 74. The method of claim 72 wherein using said data acquisitionunit further comprises using said unit at a downhole location.
 75. Themethod of claim 72 wherein using said data acquisition unit furthercomprises performing data multiplexing.
 76. The method of claim 64wherein using said at least one fiber optic sensor further comprisesusing sensors of different types.
 77. The method of claim 64 furthercomprising installing said at least one fiber optic sensor in said firstwellbore before installation of a casing therein.
 78. The method ofclaim 64 further comprising installing said at least one fiber opticsensor in said first wellbore after installation of a casing therein.79. The method of claim 64 further comprising providing programmedinstructions to a robotic device for installation of said at least onefiber optic sensor.
 80. The method of claim 79 further comprisinginstalling said at least one fiber optic sensor at a desired location.81. The method of claim 64 further comprising attaching said at leastone fiber optic sensor to a casing section prior to installation ofcasing in said first borehole.
 82. the method of claim 81 furthercomprising: (A) attaching said at least one fiber optic sensor to anadditional casing section prior to installation of casing in said firstborehole; and (B) stabbing said casing section and said additionalcasing section to facilitate communication through said casing sections.83. The method of claim 74 further comprising transmitting data fromsaid downhole data acquisition unit to a surface location using a methodselected from (i) transmission through optical fiber, (ii)electromagnetic transmission, (iii) acoustic transmission, and, (iv)wire connections
 84. The method of claim 64 further comprising makingmeasurements of a property of said earth formation using an additionalsensor selected from (i) a resistivity sensor, (ii) a gamma ray sensor,and, (iii) an acoustic sensor.
 85. The method of claim 64 furthercomprising permanently installing said at least one fiber optic sensorin said first wellbore.
 86. The method of claim 64 further comprisingusing said at least one fiber optic sensor for making measurements inone or more producing zones of an earth formation.
 87. The method ofclaim 74 further comprising using said data acquisition unit forcontrolling the operation of said tool based at least in part to ameasurement made by said at least one fiber optic sensor.
 88. The methodof claim 87 wherein controlling the operation of said tool furthercomprises one of (i) opening a sliding sleeve, (ii) closing a slidingsleeve, (iii) increasing a production rate from a producing earthformation, (iv) decreasing a production rate from a producing earthformation, (v) shutting down a producing zone, (vi) performing acleaning operation, and, (vii) performing a reaming operation.
 89. Themethod of claim 73 further comprising using said data acquisition unitfor controlling the operation of said tool based at least in part to ameasurement made by said at least one fiber optic sensor.
 90. The methodof claim 89 wherein controlling the operation of said tool furthercomprises one of (i) opening a sliding sleeve, (ii) closing a slidingsleeve, (iii) increasing a production rate from a producing earthformation, (iv) decreasing a production rate from a producing earthformation, (v) shutting down a producing zone, (vi) performing acleaning operation, and, (vii) performing a reaming operation.